In many industries, including oil, paper and pulp, textile, electricity generating and food processing, there is an ever-present problem of handling water contaminated with various substances. In particular, water is often used to aid in the production of oil and gas on offshore platforms as well as on land. This water is usually pumped into a formation in order to be able to pump oil out.
One process where water is used to recover hydrocarbons is Steam Assisted Gravity Drainage (SAGD). This process has been tested extensively in the heavy oil and bitumen reservoirs in Canada and has been generally successful, particularly in the very viscous Athabasca Tar deposits.
Athabasca Tar (also called bitumen) occurs mainly in the McMurray formation of the Lower Cretaceous, which lies unconformably on an erosional surface of Devonian carbonate rock. The matrix is mostly unconsolidated, very fine to coarse-grained, quartz sand of variable thickness. In places the sand is thick with net pay zones from 20 to 40 meters in thickness, 30-40% porosity and contains 10 to 18 wt % of bitumen. A small fraction of the deposit (<10%) is at a depth sufficiently shallow to allow recovery by open pit mining and this has become a very large industrial activity.
Prior to the demonstration of the SAGD process, several other processes for the in situ recovery of Athabasca tar were tested. These included cyclic steam stimulation, in situ combustion, electric heating, and other horizontal well processes. All of these approaches were relatively disappointing and SAGD is the only process that has shown economic potential.
The SAGD process involves a long horizontal production well located at the bottom of a reservoir. Steam is injected into a second horizontal well placed a few meters above this producing well. For very viscous bitumen it is usual to circulate steam in both wells to heat the intervening reservoir and allow communication. After communication is achieved steam is injected continuously into the upper well and condensate and heated oil are removed from the lower one. Production is restricted to allow heated oil and condensate to be produced without live steam. This form of operation is well-established and relatively simple to control. The production well must be long and horizontal so that an economic oil rate can be achieved without steam coning. Conventional vertical wells are not practical with SAGD. Rates of the order of 0.2 to 0.4 or more B/d are achieved per foot length of horizontal well (0.1 to 0.2 m3/d per meter of horizontal length). A production well 750 m long (2460 ft) may produce about 1000 B/d of Athabasca bitumen. After treatment, the produced water is reinjected.
A “Wet Steam Generator” is typically used to produce steam for SAGD operation. The produced water is normally treated to a quality level suitable as feed water to the steam generator. The feed water quality requirements are: oil less than 1 ppm; hardness (expressed as CaCO3) less than 1 ppm, suspended solid less than 1 ppm; and silica less than 50 ppm depending on the pressure rating of the steam generator. Hardness of the produced water can be economically reduced to 1 ppm or less by a zeolite softening process if the total dissolved solid (TDS) in the produced water is less than typically 5,000 ppm. Lime softening will be utilized if the TDS of the produced water is high. “Hot/warm” lime softening has added benefits, in that it will reduce/remove silica content from the produced water.
It is interesting to note that lime will react with Ca(HCO3)2 and CO2. If the produced water contains excessive alkalinity and CO2, it may be more economical to reduce/remove them prior to the lime softening process. Ca(HCO3)2 will react with H2(SO4) and produce water, CO2 and CaSO4 which will precipitate. Removing alkalinity and CO2 from the produced water will greatly reduce the lime dosage.
If the produced water contains excessive TDS, for instance greater than 5,000 ppm or higher and high silica content, e.g. 50 ppm or higher, then a typical process train for produced water treatment will consist of an oil/water separator, a flotation unit, a lime softening clarifier, a walnut filter and a weak acid ion exchanger and steam generator. If TDS is less than 5,000 ppm and silica content less than 50 ppm, then the process train will consist of an oil/water separator, a flotation unit, a walnut filter and a zeolite ion exchanger.
Apparatus for ingesting and mixing gas into a liquid body are known, such as those of U.S. Pat. No. 3,993,563, that includes a tank, a rotatable impeller fixed to a vertical drive shaft, and a vertically-extending conduit which surrounds the drive shaft and which extends to location in the liquid above the impeller to serve as a channel of communication between a source of gas and the impeller.
U.S. Pat. No. 6,660,067 to Stacy, et al. (Petreco International, Inc.) teaches that a mechanical device may be used to effectively displace a first undesired gas (e.g. oxygen) from within a liquid with a second desired or at least inert gas (e.g. nitrogen). The device is a vessel that receives the liquid containing the first gas and passes the liquid through a series of gasification chambers. Each gasification chamber has at least one mechanism that ingests and mixes a second gas into the liquid thereby physically displacing at least a portion of the first gas into a vapor space at the top of each gasification chamber from which it is subsequently removed. There is an absence of communication between the vapor spaces of adjacent chambers. The ingesting and mixing mechanisms may be a dispersed gas flotation mechanism, and may be a conventional depurator. The liquid now containing the second gas and very little or none of the first gas is removed from the vessel for use.
It would be desirable if a method and apparatus were devised that could simultaneously remove oil, gas and alkaline species from contaminated water.